At least some of the exemplary embodiments described herein relate to methods of using ampholyte polymeric compounds as friction reducing agents in subterranean operations, and treatment fluid compositions relating thereto.
During the drilling, completion, and stimulation of wellbores and subterranean formations, aqueous treatment fluids are often pumped through tubular goods (e.g., pipes, coiled tubing, etc.). A considerable amount of energy may be lost due to friction between the aqueous treatment fluid in turbulent flow and the formation, the wellbore, and/or the tubular goods located within the wellbore. As a result of these energy losses, additional horsepower may be necessary to achieve the desired treatment.
For example, in fracturing operations, a treatment fluid utilizes either an increased viscosity (e.g., a gelled fluid) or a high flow rate (e.g., a high-rate water) to create or extend one or more factures in the formation. As the treatment fluid flows across the surfaces in the formation, the wellbore, and related tubular goods, the frictional forces between the treatment fluid and surfaces are amplified relative to non-viscosified fluids under normal flow because of the increased viscosity or high flow rate of the treatment fluid. The amplified friction forces translate to a need for increasing the energy input to achieve the desired pressure and/or flow rate for the treatment fluid. Increasing energy input increases the cost of the fracturing operation.
To reduce these energy losses, friction reducing agents are in aqueous treatment fluids. However, most of the friction reducing agents are sensitive to the total dissolved solids of the local environment (e.g., either the treatment fluid or the formation fluids encountered during an operation). As used herein, total dissolved solids (“TDS”) refers to the sum of all minerals, metals, cations, and anions dissolved in water, which is differentiated from suspended solids and can be separated from suspended solids via filtration. As most of the dissolved solids are typically salts, the amount of salt in water is often described by the concentration of total dissolved solids in the water. As the TDS increases, many friction reducing agents loose function and, in some instances, may further aggravate the situation by precipitating out of the fluid.
Further, in some instances, it is desirable for the friction reducing agent to reduce the friction in the wellbore and near-wellbore areas and degrade or break at some time thereafter. To achieve this with traditional friction reducing agents, the breaker may be included in the treatment fluid, or a breaking fluid may be subsequently introduced, the latter of which increases the complexity, cost, and time associated with subterranean operations. In instances where breakers are included in the initial treatment fluid, the breakers are generally engineered to delay breaking (e.g., via encapsulation or chemical modification), which increases the cost of developing and producing the delayed breaker.
Recently, improved friction reducing systems have been developed that are multi-component systems and less sensitive to the TDS. However, implementation of these friction-reducing systems at the well site typically involves metering each component into the treatment fluid at different rates, which increases the complexity of the operations. Variations in the formulation of the friction reducing systems as a result of improper metering can result in a less effective, or ineffective, friction reduction, which in turn increases the energy requirements and costs of the operation.
Accordingly, a need exists for a friction reducing agent that is compatible with environments having higher TDS, and that are less complex to implement, preferably single-component.